Note: Descriptions are shown in the official language in which they were submitted.
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Method of enhancing oil recoverv
This invention relates to a method of enhancing oil recovery from a
subterranean hydrocarbon reservoir and to compositions for use in such
methods.
Hydrocarbons, i.e. gas and oils, are a limited resource and thus it is
important
to maximize the amount of oil that is recovered from underground reservoirs.
For certain reservoirs, particularly heavy oil reservoirs in which the oil
contains large quantities of long chain hydrocarbons, paraffins, waxes,
aromatics (including polyaromatic hydrocarbons - PAH), terpenoids,
asphaltenes, etc., oil sand or shale reservoirs, and bitumen reservoirs the
techniques currently used result in the recovery of less than 10% wt. of the
oil
in the reservoir. To a large extent this is because the oil is of such a high
viscosity, or otherwise flows so poorly, that only limited quantities will
reach
the production wells.
One approach that has been adopted to this problem is to inject superheated
steam down injection wells above the production wells, e.g. in substantially
horizontal sections of the bore holes where the injection bore hole is above
the
production bore hole. The temperature increase resulting from superheated
steam injection serves to reduce the viscosity of the heavy oil which then,
under the influence of gravity, flows more readily into the production bore
hole. This procedure has been referred to as steam-assisted gravity drainage
(SAG-D) or VAPEX.
A further approach to increasing hydrocarbon recovery is hot solvent
extraction in which a heated organic solvent is injected into the matrix to
reduce the viscosity of the hydrocarbon and improve its flow characteristics
in
the matrix. In this technique, injection may be into an injection bore hole
(i.e. as with steam injection) or it may be into the production bore hole.
Typically the hot solvent used is selected from naphtha, diesel, toluene, and
other hydrocarbon fractions. The injection temperature will typically be in
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the range 20 to 400 C, especially 80 to 100 C.
Yet another extraction enhancement procedure is cold heavy oil production
with sand (CHOPS) which involves sand influx into the production well.
Another procedure is hydraulic fragmentation (fracking) of the matrix at the
production well. Further examples of enhanced oil recovery techniques for
heavy oil, oil sand or bitumeri reservoirs include cyclic steam stimulation
(CSS), and pulsed pressure flow enhancement. Down-hole. generation of
gases to increase down-hole pressure and hence oil flow into the production
well may also involve direct contact steam generation and thermal oxidation
processes (to generate CO2 from combustion of hydrocarbons down-hole).
The techniques however are cumbersome, environmentally unfriendly and
improvements and alternatives are desirable.
We have now realized that oil recovery may be enhanced if heavy oil-
degrading microorganisms are introduced through an injection well into the
formation above or adjacent a-separate production well or into the formation
at a production well, in conjunction with other oil recovery enhancement
techniques such as steam injection, hot solvent extraction, CHOPS, fracking,
CSS, etc., as described above.
Thus viewed from one. aspect the invention provides a method of enhancing
oil recovery from a subterranean hydrocarbon reservoir, especially a heavy oil
reservoir, said method comprising injecting into said reservoir through a
matrix injection section of a well a microorganism capable of digesting oil,
and recovering oil from an oil receiving section of a production well, where
said injection section is'in said production well (e.g. at said oil receiving
section) or is in an injection well and is above or adjacent said oil
receiving
section, and wherein microorganism injection is preceded by another oil
extraction enhancing procedure (such as steam or hot solvent injection,
CHOPS, hydraulic fragmentation, etc.), particularly preferably through the
same injection section, e.g. 1 to 150 days beforehand
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Microorganism injection is especially preferably effected through a plurality
of
injection wells for the (or each) production well, e.g. 5 to 20 such injection
wells, for example using an array of "slim" injection wells each terminating
(i.e. with a matrix entry site) near a matrix exit site of the production
well, i.e.
multi-tracking injection wells. This is particularly desirable for shallow
reservoirs, e.g. at a depth of 200 to 600m subsurface. This is shown
schematically in the accompanying Figure.
By oil degrading or oil digesting it is meant that the microorganism (or
microorganism mixture) is capable of chemically modifying oil to reduce the
viscosity or wax, asphaltene or aromatics content thereof whereby to cause it
to flow more freely in the matrix (i.e. the rock from which the reservoir is
formed). Such modification will generally involve fragmentation of one or
more components of the oil (e.g. fragmentation of alkanes into smaller
alkanes), ring opening in aromatic compounds, or opening or cleavage of
other large organic compounds, for example asphaltenes. Desirably, the
microorganisms cleave or fragment the oil components so as to render the oil
viscosity sufficiently low as to enhance oil recovery. Thus it' is preferred
that
the microorganism used not simply be one that generates a surfactant or a gas
(e.g. methane), and particularly preferably a microorganism cocktail is used
which causes ring opening, especially in combination with a microorganism
that causes hydrocarbon chain shortening. Other factors remaining constant,
production flow is approximately inversely proportional to the down-hole
(heavy) oil viscosity and so degradation using the technique of the invention
may enhance liquid hydrocarbon flow by a factor of from ten to hundreds of
percent by volume.
Many microorganisms (generally eubacteria or archae) are known to digest oil
and such microorganisms may be used in the method of the present invention
if they are capable of surviving at the temperatures and pressures experienced
down-hole. "Typical examples include Bacillus sp., Thermus sp., Pseudomonas
sp., Geobacillus sp., Arthrobacter sp., Sphingomonas sp., Mycobacterium sp.,
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Burholderia sp., Acinebacter sp., Thermovirga sp., Archaeoglobus sp.,
Thermosipho
sp., Symbiobacterium sp., Methanosaeta sp., Epsilonproteobacterium sp.,
Syntrophus sp., Nocardioides sp., Deferriibacter sp., Chloraf exi sp., etc.
Preferably however the inoculate, the microorganism composition injected in
accordance with the present invention, will contain at least 2 and preferably
at
least 3 different microorganism species, in particular at least one capable of
chain-shortening alkanes and at least one capable of ring opening aromatics.
Examples of microorganisms capable of chain-shortening alkanes include
Bacillus sp., Geobacillus sp., Acinebacter sp., Methanosaeta sp. and in
particular
Acinebacter venetianus, Bacillus thermoleovorans , Bacillus aeolis and
Geobacillus
thermodenitrificans while examples of microorganisms capable of degrading
aromatics include Nocardioides sp., Geobacillus sp., and Syntrophus sp., eg
Geobacillus subterraneous. Use of Therm'us sp. will result in decrease of
aromatics, resins and asphaltenes and reduced viscosity, eg Thermus strains
SP33 C2 and TH-2 (see Hao et al. J. Can. Petrol. Tecnol. 43:36-39 (2003),
Can. J. Microbiol. 50:175-182(2004), and J. Petrol. Sci. Eng. 43:247-
258(2004)). Use of Pseudomonas sp. will result in n-alkane and PAH
degradation and reduced viscosity, eg Pseudomonas aeruginosa. Moreover,
Thermus brockii is capable of degrading hexadecane and pyrenes (see
Geitkenhauer et al., Water Sci Technol 47: 123-130(2003)).
Rather than producing a microorganism inoculation composition by mixing
(top-side or on site) individual microorganisms, it is possible and indeed
preferable to use microorganism cocktails from or developed from naturally
occurring microorganism communities, e.g. microorganism communities
from subterranean hydrocarbon reservoirs, from oil shales, bitumen sources,
or, especially from mud volcanoes. Likewise appropriate microogranisms
may of course be produced by mutagenesis or by genetic engineering.
It is especially preferred that the inoculate contain microorganisms selected
from the species Bacillus thernaoleovorans, Thernaus brockii, Syntrophus
aciditrophicus, Acinebacter venetianus, Deferribacter desulfuricans,
Thermosipho
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geolei, Thernaosipho africanus, Symbiobacterium thermophilium, Thermovirga
lienii,
Sphingonaonas stygia, Sphingomonas aromaticivorans, Sphingomonas subterranean,
Sphingonaonas yanoikuyae, Pseudomonas putida, Burholderia sp.
and Archaeoglobusfulgidus. Particular deposited strains that can be used
include Bacillus thennoleovorans AB034902 (Genbank), Bacillus aeolis
AY603079 (Genbank), Pseudomonas aeruginosa AM087130(Genbank),
Geobacillus thermodenitrificans DQ243788(Genbank), Geobacillus subterraneous
DQ355385(Genbank), Sphingomonas stygia DSMZ12445, Sphingomonas sp
DSMZ 7526, Sphingomonas sp DSMZ 11094, Sphingomonas aromaticivorans
DSMZ 12444, Sphingomonas subterranean DSMZ 12447, Sphingomonas
yanoikuyae DSMZ 6900, Pseudomonas putida NCIMB 9815, Pseudomonas
putida NCIMB 9816, Pseudomonas putida NCIMB 10015,
Methanosaeta sp. AJ 133791, Epsilonproteobacteria AY 570641, Syntrophus
aciditrophicus CP 000252, Nocardioides sp. D 87974, Deferribacter
desulfuricans
AB 086060, Chlorflexi sp. AB 074961, Therinovirga lienii DQ 071273,
Archaeoglobusfulgidus DQ 131905, Therrnosipho geolei AJ 272022, Acinebacter
venetianus ATCC 31012 and Symbiobacterium sp. AB 052392. It is
particularly preferred that it contain microorganisms of at least the species
Sphingonzonas sp., Pseudomonas sp., Burholderia sp., Thermovirga lienii,
Archaeoglobusfulgidus, Acinebacter venetianus, Thermosipho geolii and
Symbiobacterium sp. Such mixtures are new and form a further aspect of the
invention. Viewed from this aspect, the invention provides a microorganism
mixture for hydrocarbon reservoir treatment, said mixture comprising
microorganisms of at least two, preferably at least three, of the following
species: Sphingomonas sp., Pseudomonas sp., Burholderia sp., Thernaovirga
lienii,
Archaeoglobus fulgidus, Acinebacter venetianus, Thermosipho geolii and
Symbiobacterium sp, in particular a said mixture further comprising vitamins
and minerals and preferably a mixture in liquid or dry powder form, and
preferably alkane-free, eg isolated from any matrix or hydrocarbon in which it
may occur naturally.
In particular, a combination of Sphingomonas sp., Pseudomonas sp., and
Burholderia sp. may be used, eg Sphingomonas stygia, Sphingomonas
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aromaticivorans, Sphingomonas subterranean, Sphingomonas yanoikuyae ,
Pseudomonas putida, and Burholderia sp., especially Sphingomonas stygia
DSMZ12445, Sphingomonas sp DSMZ 7526, Sphingomonas sp DSMZ 11094,
Sphingomonas aromaticivorans DSMZ 12444, Sphingomonas subterranean
DSMZ 12447, Sphingomonas yanoikuyae DSMZ 6900, Pseudomonas putida
NCIMB 9815, Pseudomonas putida NCIMB 9816, Pseudomonas putida
NCIMB 10015, and Burholderia sp.
For shallow oil fields it may be adequate to use in the inoculate
microorganisms that grow at atmospheric pressure, however for deeper fields
it is important that the microorganism be both thermophiles and piezophiles.
Selecting appropriate combinations of microorganisms for use in shallow
fields is thus relatively simple. A candidate microorganism or microorganism
cocktail may be incubated with a sample of heavy oil, preferably from the site
to be treated, and if a reduction in viscosity is achieved the candidate may
proceed. For deeper fields the incubation is preferably effected at the down
hole temperatures and/or pressures of the site to be treated. In both cases,
the ability to withstand temperatures of 60 to 120 C, especially 70 to 100 C
is preferred as such microorganisms may readily be injected into sites where
steam or hot solvent injection has been, is being or is to be effected :
otherwise a significant delay between steam or hot solvent injection and
microorganism injection may be required.
Where steam or hot solvent injection is to be used in the method of the
invention, the timing of the microorganism injection should be. such that the
microorganisms are not injected into an enviroriment in which the
temperature is lethal. The delay time for microorganism injection may readily
be calculated from the heat dissipation characteristic of the matrix.
Screening of a microorganism cocktail is preferably done repeatedly, with an
aliquot of the culture at the end of one digestion period then being presented
with a fresh heavy oil sample to digest. This is important as degradation may
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require the contribution of one microorganism species after that of another
and it may thus be necessary that, down hole, all of the necessary species
continue to grow. Where, after several digestions, the microorganism
population is stable, the candidate may be developed further.
Before down hole injection, the microorganism inoculate is preferably mixed
with oil to prime its enzyme systems. '
Down hole injection of the microorganism may if desired be preceded by,
accompanied by or followed by down hole injection of nutrients for
microorganism growth, e.g. minerals and amino acids, or oil digesting
enzymes. The injection of further carbon sources, eg ones such as acetate
which are water-soluble, is particularly preferred.
Down hole injection of the microorganism may if desired be preceded by
fracturing of the matrix around the injection site, e.g. to provide a
reservoir
for microorganism growth.
Down hole injection of the microorganism into an injection well is preferably
effected in conjunction with steam or superheated water or organic solvent
injection down the same injection well, e.g. at an injection temperature of
100-400 C. This injection may precede microorganism injection (where the
steam or solvent injection temperature is lethal to the microorganisms) or may
occur simultaneously; however it is preferred that the enhanced oil recovery
technique, steam or hot solvent injection, be effected before microorganism
injection, e.g. a period of up to 1 year, for example 1 to 150 days,
preferably 5
to 20 days, beforehand. Particularly desirably, the enhanced oil recovery
technique (eg steam or hot solvent injection) and microorganism injection are
effected repeatedly, in particular in specifically designed sequenced
procedures.
Down hole injection of the microorganism into a production well is preferably
effected in conjunction with the enhanced oil recovery technique, e.g.
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CHOPS, hot organic solvent injection, hydraulic fragmentation, etc.; this may
precede microorganism injection or be performed simultaneously or later. In
the case of hot solvent injection, solvent injection is preferably effected
beforehand with a sufficient time delay that the matrix temperature is
tolerable to the microorganisms when they are injected, e.g. a delay of up to
1
year, for example 1 to 150 days, especially 5 to 20 days. Such treatments of a
production well are preferably repeated.
Particularly preferably, microorganisms are injected into both injection and
production wells, in each case preferably in conjunction with a further
hydrocarbon extraction enhancing technique (i.e. SAG-D, CHOPS, etc).
If desired the microorganism inoculate may include microorganisms which
generate gas and/or acid and hence degrade the matrix.
The method of the invention can serve to reduce the usage or aggressiveness
of the other hydrocarbon extraction enhancing techniques, such as SAG-D
and so reduce their environmental impact.
The invention is especially applicable to hydrocarbon reservoirs which yield
heavy oils, e.g. from medium crude (31-22 API) to heavy crude (22-10 API)
to extra heavy crude (< 10 API) oils, and the microorganism treatment,
particularly with thermophilic and/or piezophilic microorganisms, is
preferably in conjunction with, e.g. simultaneously or sequentially, at least
one of SAG-D, CHOPS, VAPEX, hot solvent extraction and hot water
extraction.
The invention will now be illustrated by the following non-limiting Examples
and the accompanying drawings, in which:
Figure 1 is a schematic vertical section through a shallow heavy oil
reservoir;
and Figure 2 is a chart of oil recovery and oil viscosity without and with
treatment according to the invention.
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Referring to Figure 1 there is shown an offshore platform 1 having a producer
well 2 extending into a shallow heavy oil reservoir 3. From platform 1 a
series
of slim injector wells 4 are fed by injection unit 5 which serves to inject
steam
and microorganism culture sequentially.
Example 1
Treatment of Zuata crude oil with microorganisms endogenous to Ar e~; ntine
bitumen
Materials:
Bitumen (from Argentina)
Treatment medium 1 (TMS 1) content per litre: 5 g FeSO4 =7H20, 0.29 g
CuSO4 =5H20, 0.44 g ZnSO4 =7H20, 0.15 g MnSO4 H20, 0.01 g
Na21VIoO4 =2H20, 0.02 g CoC12 =6H20, 50 ml conc HCI.
Treatment medium 3 (TMS3) content per litre: 2021.2 mg Na2SiO3 =9H20,
445.5 mg NaF, 5651.7 mg K2B407 4H20, 47.9 mg Na103, 180.7 mg
KAl(S04)2 =12H20, SnCl2 =2H2O.
Treatment medium 4 (TMS4) content per litre: 346.8 mg NiCI2 =6H2O,
101.4 mg Na2SeO3 =5H2O, 18 mg V2O5, 14 mg K2Cr2O7, 3.6 mg
Na2WO4 =2H2O.
Vitamin stock solution (VSS) content per litre: 2.00 g biotin, 2.00 g folic
acid,
10.00 g pyridoxine-HCI, 5.00 g thiamine-HCI =2H20, 5.00 g riboflavin, 5.00 g
nicotinic acid, 5.00 g D-Ca-pantothenate, 0.10 g vitamin B12, 5.00 g p-
aminobexizoic acid, 5.00 g lipoic acid.
Mineral medium (MM) content per litre: 0.9 g NH4NO3, 0.05 g
CaCI2 =2H20, 0.2 g MgSO4 =7H20, 3.06 g Na2HPO4 =2H20, 1.52 g KH2PO4,
1 ml TMS1, 1 ml TMS3, 1 xrril TMS4, 1 ml VSS. pH adjusted to pH 7Ø
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Process medium 1 (PM1): Zuata crude oil (from Venezuela) 0.4 %(w/vol) in
MM
Process medium 2 (PM2): Zuata crude oil 1.6% (w/vol) in Light Gas Oil
(LGO), 1 % (vol/vol) in MM
Inoculation:
Bitumen samples (0.5 g) were inoculated into shakeflasks (Bellco, 250 ml)
containing 50 ml PM1 or PM2.
Cultivation:
The shake flasks were incubated at 50 C on a rotary shaker at 200 rpm and
90 % humidity (Infors Multitron incubator) for 34 days.
Example 2
Treatment of Zuata heavv oil with microorganisms endogenous to a mud
volcano
Materials:
Mud from mud volcano
Widdel Basal Salt Media B (WBSB) content per litre: 30.0 g NaC1, 0.15 g
CaC12 =2H2O, 3.0 g MgC12 =6H2O, 0.9 g NH4NO3, 0.5 g KCl, 0.18 g Na2SO4,
3.06 g Na2HPO4 =2H20, 1.52 g KH2PO4, 1 ml TMS 1, 1 ml TMS3, 1 ml
TMS4, 1 ml VSS. pH adjusted to 8.2.
Process medium 3 (PM3): Zuata crude oil dissolved 10% (w/vol) in
heptamethyl nonane (HMN - an inert solute) added 5% (vol/vol) to WBSB
Inoculation:
Mud samples (0.5 ml) were inoculated into shakeflasks (Bellco, 250 ml)
containing 50 ml PM3.
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Cultivation:
The shake flasks were incubated at 50 C on a rotary shaker at 200 rpm and
90 % humidity (Infors Multitron incubator) for 28 days.
Example 3
Treatment of Linerle crude oil with microorganism cocktail
Materials:
Microorganism cocktail (MC): A mixture of the following strains:
Pseudomonas putida NCIMB 9815, NCIMB 9816 and NCIMB 10015 and
Burkholderia sp isolates from bio-sludge from a refinery water treatment
plant.
The microorganisms were cultivated in inoculum medium (IM) for up to 24
hours and harvested by centrifugation (10 min, 5 000 x g). The cell-pellets
were washed twice with MM medium (20 ml) and the pellet resuspended in
MM medium (500 l).The microorganism cocktail (MC) was prepared by
mixing the washed and resuspended microorganisms in equal concentrations.
Inoculum medium (IM) per litre: 20.0 g yeast extract, 1.0 g MgSO4 =7H2O, 5
g NaCI, pH adjusted to 7.5.
Process medium 4 (PM4): 5 % (vol/vol) heat-treated Linerle crude oil (from
the Norwegian continental shelf, heated to 60 C for 2 hours) was added to
MM.
Process medium 4 with yeast extract (PM4-YE): 5%(vol/vol) heat-treated
Linerle crude oil (from the Norwegian continental shelf, heated to 60 C for 2
hours) was added to MM containing 0.1 g yeast extract.
Inoculation:
The MC was inoculation into shakeflasks (Bellco, 250 ml) containing 50 ml
PM4 or 50 ml PM4-YE to a final OD660 = 1Ø
Cultivation:
The shake flasks were incubated at 30 C on a rotary shaker at 200 rpm
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(Infors Multitron incubator) for 9 days.
Example 4
Treatment of Zuata heavy oil in sand with microorganisms from sediment
Materials:
Microorganism inoculum (MI): A mixed inoculum of microorganisms
isolated from sediment samples
Sand column: Zuata crude oil mixed in a 9:36 weight ratio with barskarp
sand, packed into glass columns (Omnifit).
Inoculation:
MI (5 ml, approx 109 cells/ml) was added to the sand column after water
flooding the column for 4 days.
Cultivation:
After inoculation, the sand columns were shut-in for 24 hours prior to
circulation of MM was initiated. MM was circulated at a rate of 171 ml/hour.
The results of this treatment of heavy oil in reservoir-like conditions is
shown
in Figure 2 of the attached drawings. Figure 2 shows the oil recovery from
sand packs as a percentage of standard total original in place (STOOIP - right
hand ordinate and plot) and the viscosity in mPa.s of the treated oil at a
shear rate of 100 s-1 and 55 C (left hand ordinate and bar chart). The left
hand values are for Zuata heavy oil without treatment. The centre values are
for Zuata heavy oil treated under the conditions specified in this Example.
The right hand values are for Zuata heavy oil treated under the conditions
specified in this Example, but with the addition of 5 g/L acetate (eg sodium
acetate) to the MM.
Example 5
Viscosity effect on crude oils
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The viscosity of treated and untreated heavy crude oil type 1 was determined
at 30 C at a shear of up to 1000 s-1. While untreated gave a viscosity value
of
417 mPas, for the treated sample this was reduced to 130 mPas. In a further
test using Zuata crude oil, treated and untreated, in a radial reservoir
model,
at 60 C and a shear rate of up to 700 s-1, a significant reduction in
viscosity
was noted at all shear rates which became increasingly prominent at shear
rates above 100 s-1.
